Field of Endeavor
The present invention relates to a method for the operation of a power plant system having a power plant for the generation of electricity, in particular of a combined cycle power plant or a steam power plant operated with fossil fuels, a carbon dioxide capture and compression system, and an external heat cycle system. It furthermore relates to a power plant system useful for practicing the method.
Brief Description Of The Related Art
Conventional fossil fuel-burning power plants use a steam cycle for power generation, in the case of the use of gas turbines, in a so-called combined cycle power plant, in combination with gas turbines. Steam cycles are also used in newer power plants, such as Integrated Gasification Combined Cycle (IGCC) power plants or Natural Gas Combined Cycle (NGCC) power plants. In a coal-fired steam cycle power plant, about 40% of the heat energy contained in the fossil fuel is converted to electricity. This leaves a large portion of the energy wasted in the water cooling towers or other water cooling facilities. The water cooling facilities transfer all of the waste heat in the low pressure exhaust steam to the environment through the vaporization of cooling water. Combined power plants have a somewhat higher overall efficiency, up to 59%.
On the other hand, CO2 separation from post-combustion flue gas requires a large amount of heat (in the form of steam). For example, the current state-of-the-art monoethanol amine (MEA) absorption process requires about 4 MJ of total heat for every kilogram of CO2 captured.
CO2 separation processes thus are energy intensive. The required energy is provided by steam in the power plant. The extraction of steam from the steam turbine reduces the electricity generation (output, overall efficiency). For the same amount of steam, the higher the pressure (and thus the temperature) of the extracted steam is, the higher the loss of the electricity will be. State-of-the-art amine-based absorption processes reduce electricity output.
This energy cost, and the associated financial cost, inhibits the adoption of CO2 separation. With conventional MEA-based absorption processes, the cost of CO2 separation from post-combustion flue gases requires a significant amount of the total CO2 sequestration cost. High separation cost is the main reason for the delay in CO2 emission control. High CO2 separation cost is also hindering the acceptance of CO2 based Enhanced Oil Recovery technology.
The implementation of a CO2 capture and compression system on a combined cycle or steam power plant leads to a drop of its overall efficiency. The CO2 capture process requires heating and cooling facilities, which are respectively provided by steam extraction and main cooling water or another cooling source. The CO2 compressor requires either electricity if it is driven by electrical motor or steam if driven by an auxiliary steam turbine. The CO2 compression further requires a capability for cooling the CO2.
Extensive studies have been conducted in the area concerning CO2 capture as reflected in the following publications. U.S. Patent App. Pub. Nos. 2007/0256559, 2007/0213415, and 2006/0032377 describe CO2 capture processes. Specifically, U.S. Patent App. Pub. No. 2007/0256559 describes that the condensate from the amine reboiler is directly sent back to the main condensate line. U.S. Patent App. Pub. No. 2006/0032377 proposes to flash the condensate coming from the amine reboiler, and to use the steam phase in a “semi-lean regenerator”.
The prior art describes the use of main cooling water from a cooling tower or another cooling source to dump the heat from the CO2 capture and compression system. Air could also be an alternative cooling media. The cooling concept increases the efficiency of the CO2 compression unit due to low inlet temperatures to the compressors.
A known concept for a power plant system with a power plant, a CO2 capture system and a district heating includes the use of steam extraction from the power plant steam turbine or boiler as shown schematically in FIG. 1.
FIG. 1 shows a power plant system with a power plant 6, which can be a steam power plant or a combined cycle power plant, and that directs its exhaust gas containing carbon dioxide via a line 27 to a carbon dioxide capture plant 5. In this carbon dioxide capture plant 5 an amine solution is cycled as an absorber liquid, where in a first cycle stage this absorber solution is in contact with the exhaust gases and absorbs the carbon dioxide. It is then fed through line 26 by a pump 16 and fed through an amine reboiler 4, where it is heated such that it releases the carbon dioxide in highly concentrated form. The concentrated carbon dioxide is subsequently fed via line 20 to a compression and cooling unit 13. The compressed CO2 is finally taken to a storage facility 10. In this example, there is provided a sequential compression system with sequential compressors 15 driven by a motor M, wherein intercoolers 7 are arranged between the compressors 15 and a precooler 12 is arranged upstream of the first compressor. The cooling medium for the intercoolers 7 is directed via a cooling water line 8 to a cooling tower 9, where the heat of the cooling medium is dissipated to the atmosphere.
The heating in the amine reboiler 4 is facilitated by steam generated in the water steam cycle of the power plant 6. A first steam extraction line 23 from the water steam cycle of the power plant 6 leads to heat exchanger or amine reboiler 4 for heating of the CO2 absorber solution. The return flow from the reboiler 4 is directed through line 25 and 24 to the power plant 6, where the condensate return lines typically include a feed water tank, various preheaters, and a pump 16.
A further steam extraction line 17 leads from the water steam cycle of the power plant 6 to a conventional heat exchanger CHEX, in which heat from the steam extraction is transferred to a heating medium in a cycle line 28 of a client network or external heat cycle system such as a district heating system. The system includes an inflow from a unit 11 and an outflow to a unit 19.